Liquefaction of Associated Gas at Moderate Conditions

ABSTRACT

A method is proposed for converting a portion of associated gas generated during crude oil production into a liquid form which permits the transport of a large amount of methane at moderate temperatures.

This application is a continuation of and claims priority to applicationSer. No. 11/300,802, filed Dec. 14, 2005. This application claimspriority to and benefits from the foregoing, the disclosure of which isincorporated herein by reference.

TECHNICAL FIELD

The present invention resides in the methods for recovering, treatingand using natural gas.

BACKGROUND OF INVENTION

The present invention relates to a method for enhancing the value ofassociated gas produced in a remote location. Frequently, a quantity ofgaseous hydrocarbons is produced during the production of crude oil froma crude oil resource. Historically, these gaseous hydrocarbons wereoften flared at the well during production of the crude, particularlywhen the well was in a remote location, and liquid products (such ascrude oil) from the well were transported large distances to therefinery or to the market for the products.

Flaring of the gases is not acceptable, both from a resource standpointand from an environmental standpoint, and other methods for dealing withthe gases is required. When the gas quantities are large enough to makelarge scale gas processing economically feasible, the associated gas maybe liquefied in an LNG process, compressed to high pressures in a CNGprocess or converted to liquid hydrocarbons in a GTL process.

U.S. Pat. No. 6,793,712 teaches forming C₂ ⁺ rich liquid in a coolingstage during the liquefaction of natural gas, and removing the C2+ richliquid via gas-liquid separation means. As taught, the sequentialcooling of the natural gas in each stage is generally controlled so asto remove as much as possible of the C₂ and higher molecular weighthydrocarbons from the gas to produce a gas stream predominating inmethane and a liquid stream containing significant amounts of ethane andheavier components.

Natural gas typically contains up to 15 vol. % of hydrocarbons heavierthan methane. Natural gas liquids (NGL) are comprised of ethane,propane, butane, and minor amounts of other heavy hydrocarbons.Liquefied natural gas (LNG) is comprised of at least 80 mole percentmethane; it is often necessary to separate the methane from the heaviernatural gas hydrocarbons. It is desirable conventionally to recover theNGL because its components have a higher value as liquid products, wherethey are used as petrochemical feedstocks, compared to their value asfuel gas. NGL is typically recovered from LNG streams by many well-knownprocesses including “lean oil” adsorption, refrigerated “lean oil”absorption, and condensation at cryogenic temperatures. The most commonprocess for recovering NGL from LNG is to pump and vaporize the LNG, andthen redirect the resultant gaseous fluid to a typical industry standardturbo-expansion type cryogenic NGL recovery process.

The present process is directed to the recovery and preparation ofassociated gas from crude oil resources which contain relatively smallamounts of gas, such that the large scale gas processing methods areuneconomical. In the process, a crude liquefied gaseous mixture isprepared to be stable at relatively moderate temperatures and pressures,while containing a high amount of valuable methane (C₁), ethane (C₂) andpropane plus (C₃+) components.

SUMMARY OF THE INVENTION

The present invention provides a method for converting a portion ofassociated gas generated during crude oil production into a liquid formwhich permits the transport of a large amount of methane at moderatetemperatures. Thus, a method is provided for producing a methanecontaining liquid at moderate temperature, the method comprising thesteps of: recovering an associated gas from a crude oil productionprocess; drying the associated gas to remove water; chilling the driedassociated gas; separating the chilled dried associated gas at a targettemperature and target pressure in a vapor-liquid separator into amethane lean liquid stream and a methane rich vapor stream, the methanelean liquid stream containing at least 30% C2−; and storing the methanelean liquid stream.

At the target temperature of the methane lean liquid stream which ispre-selected to permit the handling and shipping of the liquid stream attemperatures and pressures normally encountered with liquefied petroleumgas (LPG), the liquid stream contains between 30% and 70% C2−components. In this way, large amounts of methane can be shipped from aremote location to a market or refinery without requiring the extremecryogenic conditions of LNG.

In one embodiment, the methane that remains as a methane rich vaporstream may be suitably used as a utility fuel for the uses selected fromthe group consisting of to drive gas turbine generators, to supply powerrequirements for living quarters and other utilities and to energizeprocess support equipment and gas fired heaters. The methane rich vapormay further or alternatively be used as a utility fuel to provide powerfor dynamic position thrusters installed on a dynamically positionedFPSO.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates the process of the invention for recovering amethane-containing liquid stream from an associated gas feed stream. Theliquid stream has the properties permitting it to be stored andtransported at relatively moderate temperature and at a relatively lowpressure.

DETAILED DESCRIPTION OF THE INVENTION

In the present method, an associated gas is treated to prepare aliquefied gas stream, containing a high amount of C2− components, whichcan be stored at relatively mild conditions of temperature and pressure.Thus, in one embodiment, the liquefied gas stream produced in anoffshore facility may be conveyed through commercially available hosesand transported to shore in a conventional LPG tanker and/or a modifiedsupply boat and/or a modified crude oil shuttle tanker. For example, LPGtankers typically have the capability of transporting liquefied gases atconditions of temperatures greater than −55° F. and at pressure below500 psia.

As used here, C1 refers to a hydrocarbon molecule containing one carbonatom. Methane is an illustrative example. C2 refers to a hydrocarbonmolecule containing two carbon atoms. Ethane is an illustrative example.C3 refers to a hydrocarbon molecule containing three carbon atoms.Propane is an illustrative example. C4 refers to a hydrocarbon moleculecontaining four carbon atoms. Butane is an illustrative example. C5refers to a hydrocarbon molecule containing five carbon atoms. Pentaneis an illustrative example. C6 refers to a hydrocarbon moleculecontaining six carbon atoms. Hexane is an illustrative example.Molecules with larger numbers of carbon atoms are defined accordingly.As used here, LPG is a term of art referring to a liquid phase mixturecomprising primarily C3 and C4 components. LNG is a term of artreferring to a liquid phase mixture comprising primarily C1 components,with lesser amounts of C2 components. Natural gas liquids, NGL, is aterm of art referring to a liquid phase mixture comprising principallyC4+ components.

As used herein, C2+ represents hydrocarbons containing two or morecarbon atoms per molecule. Non-limiting exemplary C2+ hydrocarbonsinclude ethane (C2H6), propane (C3H8), butane (C4H10), pentane (C5H12),hexane (C6H14), heptane (C7H16), octane (C8H18), and cyclic orunsaturated variants thereof. C2− represents hydrocarbons containing twoor fewer carbon atoms per molecule. C3+, C4+ are defined accordingly.

As an overview, FIG. 1 illustrates a preferred exemplary embodimentutilizing the method of the present invention. An associated gas isrecovered in step 10 from a crude oil production process. Typically, gasstream 15 is delivered to the gas processing system at a pressuregreater than 250 psia, or greater than 500 psia, or even greater than1000 psia. These pressures can be obtained naturally from a gas well orobtained by adding energy through the use of one or more compressors.Thus, in one embodiment, the entire process is maintained without noadditional pressurization of the gas or liquid streams during theprocess. In a separate embodiment, a pump or compressor is installed inthe process. For example, the compressor (not shown in FIG. 1) may beinstalled to pressurize, for example, the gas in stream 15, or in stream25 or in stream 45. The choice of stream is an engineering choice.However, it is preferred that the produced gas 15 prior to dehydration,or the dried stream 25 prior to chilling, be increased in pressure up toa target pressure. In an embodiment of the invention, the targetpressure is selected to ensure that a liquid methane lean stream beproduced in the process having a temperature in the range of between−55° F. and 5° F., and a pressure of less than 500 psia.

The associated gas (15) is then dried to remove water in step 20. Thedried associated gas (25) is pressurized in step 30 and then chilled instep 40 to liquefy a portion thereof. The chilled stream (45) comprisingboth a liquid portion and a gaseous portion is separated in step 50 intoa methane rich vapor stream (55) and a methane lean liquid stream (57),which is stored in storage vessel (60). As shown in the embodimentillustrated in FIG. 1, at least a portion of the chilled methane richvapor stream (55) is passed to the chilling step (40) to cool theincoming dried associated gas prior to its chilling. The methane leanstream (57) has a lower concentration of methane than the associated gasfeed (15), and the methane rich stream (55) has a higher concentrationof methane than the associated gas feed (15). In one embodiment, themethane lean stream is a liquid stream containing at least 40% C2−,while remaining stable to volatilization at the moderate temperaturesand pressures of the process. Thus, the methane lean stream can bestored in insulated containers and transported at relatively mildconditions without significant loss to evaporation. The methane richvapor stream may be used, for example, for providing power, forreinjection into the reservoir, and the like.

Among other factors, the present invention is based on the discoverythat heavy gaseous hydrocarbons condensed from an associated gas can beused to absorb light gaseous hydrocarbons, such as methane and ethane,while maintaining a relatively low vapor pressure. The naturallyoccurring heavy ends in the condensed stream allow methanes and ethanesto condense and be stored as liquids in a multi-component mixture atmoderate pressures and temperatures. At such conditions, CO2 removal,complex chilling/cold recovery process, distillation/fractionationprocess and handling of ultra-low temperature cryogenic liquids (such asLNG) is avoided, making the offshore (and/or) remote facility simple andsafe to operate and maintain. This unfinished liquid product called“Liquefied Heavy Gas” can be easily transported from a remote (and/or)offshore location and processed further at an onshore processingfacility into finished products such as LPG, natural gas liquids andpipeline export gas. The remaining uncondensed hydrocarbons are usefulfor satisfying internal fuel requirements.

For example, the feed gas to the process can contain CO2 at levels up to5% when the heavy liquid product is prepared at the target temperatureand pressure, with C02 levels of up to 2% being preferred.

Associated gas is a natural gas which is found in association with crudeoil, either dissolved in the oil or as a cap of free gas above the oil.Associated gas typically separates from the crude oil during production,and is recovered as a separate gaseous phase from the crude oil liquidphase. The characteristics of the associated gas depends on the fieldfrom which it is recovered, the nature of the crude oil with which it isproduced, and the temperature and pressure of the crude oil as it isproduced and stored. In general, associated gas comprises C1+components, and may include trace amounts of hydrocarbons up to C10 oreven higher. Most of the hydrocarbons in associated gas are in the C1-C6range.

Associated gas is separated from the produced crude at any time duringthe production, handling and storage of the crude, though most isrecovered as a separate phase during crude production from thereservoir. Methods for recovering associated gas are well known andpracticed in most producing wells.

The present process is beneficially practiced for processing associatedgas produced in a remote location. Such remote locations aresufficiently separated from the market that delivering the gas to marketthrough a pipeline is expensive and/or technically difficult relative totransporting the associated gas by water, including ships, barges,tankers and the like or by overland vehicle, including by trucks, trainsand the like.

In general, associated gas contains water vapor, which is preferablyremoved prior to chilling. Methods for removing water from associatedgas are well known. In one illustrative embodiment, the water is removedusing glycol as the absorbent, optionally in combination with amolecular sieve to reduce the water to the levels required by theprocess. Thus, water is removed from natural gas upstream of thecryogenic plant by glycol dehydration (absorption) followed by amolecular sieve (adsorption) bed. Alternatively, a molecular sieve bedalone, or in combination with other conventional methods, may be used toremove the water. Molecular sieve dehydration units are normallyinstalled upstream of the cryogenic plant to eliminate the water beforethe gas enters the cooling train. An exemplary molecular sieve which isuseful for this drying step is an X-type zeolite adsorbent.

The dried associated gas is chilled to condense a portion of the gas,forming a partially liquid phase product. The temperature to which theassociated gas is chilled depends on a number of factors, including theamount of the methane rich vapor phase component needed for power, andthe temperature and pressure of the methane lean liquid component whichcan be tolerated while the liquid component is being transported fromthe remote site. In one embodiment of the process, the associated gas ischilled to a target temperature, which is pre-selected to produce aliquid phase methane lean product which can be shipped to a shuttletanker (or supply boat) using commercially available marine hoses.Associated gas chilling is achieved using, for example, an adiabaticprocess (such as Joule Thomson process), an isentropic process(turbo-expander) or an external refrigeration process. Storing andshipping the methane lean liquid component is facilitated when thecomponent is stored under pressure. As with the temperature, a targetpressure is pre-selected to maintain the methane lean component in theliquid phase during storage and shipping. Pressurizing the associatedgas is typically done prior to the chilling step. In another embodiment,the temperature and pressure conditions of the separator are set suchthat the volumetric rate of methane rich gas leaving the separatorcorresponds to the flowrate required to satisfy internal fuel gasconsumption, with the remainder being condensed as liquefied heavy gaswhich is stored in pressurized vessel(s) or containers and transportedto consumers.

The chilled stream from the chilling step is then separated into amethane lean liquid stream and a methane rich vapor stream using aliquid vapor separator. The temperature and pressure of the separationare set by targets desired for shipping the liquid stream. In oneembodiment, the target temperature of the methane lean liquid phase isgreater than −55° F., and typically ranges from 5° F. to −50° F.(depending upon the demand of the internal fuel gas requirement).Likewise, while the process can be used to prepare a methane lean liquidphase having a pressure of less than 750 psia, a pressure of less than500 psia is preferred, and a pressure in the range of 220 psia to 450psia is preferred. A higher internal fuel gas demand can be met byincreasing the separator temperature, thereby producing more gas andcorrespondingly less liquefied heavy gas. In one embodiment, theseparator pressure is set at a pressure lower than the storagevessel/container maximum allowable operating pressure to account forpossible increases in pressure over time due to boil off gas generatedfrom heat ingress into the system.

In one embodiment, the separation is performed in a single stage vaporliquid separation, and without fractional distillation. Gravityseparators, centrifugal separators and the like are ideal for theseparation. Though having a reduced methane content relative to theassociated gas feed to the process, the methane lean liquid phasecontains a significant amount of C2− material. Generally, the methanelean liquid contains at least 30% C2−, more preferably in the range of30% to 65% C2−, and most preferably in the range of 40 to 60% C2−. Themethane rich vapor contains less than 30% C2+, preferably less than 25%C2+ and most preferably less 15% C2+. As used herein, percentage amountsare referenced to molar percentages, unless stated otherwise. Thestorage vessel/container is generally thermally insulated to minimizeheat ingress and thereby delay the rise in pressure over time. Thenaturally occurring C3+ heavy components in the liquids assist incondensing the methane and ethane components at relatively moderatetemperatures which may then allow the use of commercially availableflexible marine hoses to unload the liquefied heavy gas from an offshorefacility to supply boats/shuttle tanker.

The methane lean liquid phase is stored at a target temperature and at atarget pressure. In one embodiment, the target temperature of themethane lean liquid phase is greater than −55° F., and typically rangesfrom 5° F. to −50° F. (depending upon the demand of the internal fuelgas requirement). Likewise, while the process can be used to prepare amethane lean liquid phase having a pressure of less than 750 psia, apressure of less than 500 psia is preferred, and a pressure in the rangeof 220 psia to 450 psia is preferred.

The gaseous portion which is separated from the chilled associated gasesis methane rich relative to the dried associated gases. In thispreferred exemplary embodiment, this chilled gas portion is used to coolincoming dried associated gas which is to be sent to the chilling step.After removing heat, this methane rich gas portion may then be used toenergize the production facility, such as by installing gas turbinebased power generators and/or gas engine/turbine based compressordrivers and/or gas fired heaters to satisfy process heat load. Tomaximize use of gas as internal fuel for floating offshore facilitiessuch as a Dynamically Positioned FPSO, all marine power requirements(including dynamic positioning thrusters) under operations using themethane rich stream are sourced from topsides gas turbine generators (inlieu of utilizing the ship's marine fuel oil fired power generators)which also provide power to the production facilities. These powergenerators may have dual fuel capability to support start-up and otheroff design cases. Alternatively, if surplus gaseous methane rich streamstill exists after satisfying internal fuel consumption then a portionof gas may be converted to CNG. Or surplus gas is converted toadditional power and exported to third party else, a portion could beused for needed energy purposes with remainder converted to CNG.Moreover, a portion of the gaseous portion could be reinjected in asubterranean formation.

The liquefied heavy gas is an unfinished product which contains amixture of components ranging from methane to C5+ components which isthen transported to an onshore gas processing facility or a refinerywhich fractionates the liquefied heavy gas into finished products suchas pipeline specification gas, LPG and stabilized NGL.

1. A method for producing a methane containing liquid at moderatetemperature, the method comprising the steps of: a. recovering anassociated gas from a crude oil production process; b. drying theassociated gas to remove water; c. chilling the dried associated gas; d.separating the chilled dried associated gas at a target temperature andtarget pressure in a vapor-liquid separator into a methane lean liquidstream and a methane rich vapor stream, the methane lean liquid streamcontaining at least 30% C₂−; and e. storing the methane lean liquidstream.
 2. The method of claim 1 wherein the target temperature isbetween 5° F. and −55° F. and the target pressure is less than 750 psia.3. The method of claim 2 wherein the target temperature is greater than−55° F.
 4. The method of claim 2 wherein the pressure is less than 500psia;
 5. The method of claim 2 wherein the pressure is in the range ofbetween 220 psia to 450 psia.
 6. The method of claim 1, wherein themethane lean liquid stream contains between 30% and 70% C₂− components.7. The method of claim 6, wherein the methane lean liquid streamcontains between 40 and 60% C₂− components.
 8. The method of claim 1wherein the methane rich vapor stream comprises less than 30% C₂+hydrocarbons.
 9. The method of claim 6 wherein the methane rich vaporstream comprises less than 15% C₂+ hydrocarbons.
 10. The method of claim1 wherein the associated feed gas comprises greater than 30% C₂+hydrocarbons.
 11. The method of claim 8, wherein the associated feed gascomprises greater than 40% C₂+ hydrocarbons.
 12. The method of claim 1wherein the dew point of the dried associated gas is less than thetarget temperature.
 13. The method of claim 1, further comprising usingthe methane rich vapor as a utility fuel for the uses selected from thegroup consisting of to drive gas turbine generators, to supply powerrequirements for living quarters and other utilities and to energizeprocess support equipment and gas fired heaters
 14. The method of claim1, further comprising using the methane rich vapor as a utility fuel toprovide power for dynamic position thrusters installed on a dynamicallypositioned FPSO.